1. Field of the Disclosure
The present disclosure generally relates to a connector establishing a fluid-tight connection to a downhole tubular. More particularly, the present disclosure relates to a connector establishing a fluid-tight connection between a downhole tubular and a lifting assembly. Alternatively, the present disclosure relates to a connector establishing a fluid-tight connection between a downhole tubular and another tubular.
2. Description of the Related Art
It is known in the industry to use a top-drive assembly to apply rotational torque to a series of inter-connected tubulars (commonly referred to as a drillstring comprised of drill pipe) to drill subterranean and subsea oil and gas wells. In other operations, a top-drive assembly may be used to install casing strings to already drilled wellbores. The top-drive assembly may include a motor, either hydraulic, electric, or other, to provide the torque to rotate the drillstring, which in turn rotates a drill bit at the bottom of the well.
Typically, the drillstring comprises a series of threadably-connected tubulars (drill pipes) of varying length, typically about 30 ft (9.14 m) in length. Typically, each section, or “joint” of drill pipe includes a male-type “pin” threaded connection at a first end and a corresponding female-type “box” threaded connection at the second end. As such, when making-up a connection between two joints of drill pipe, a pin connection of the upper piece of drill pipe (i.e., the new joint of drill pipe) is aligned with, threaded, and torqued within a box connection of a lower piece of drill pipe (i.e., the former joint of drill pipe). In a top-drive system, the top-drive motor may also be attached to the top joint of the drillstring via a threaded connection.
During drilling operations, a substance commonly referred to as drilling mud is pumped through the connection between the top-drive and the drillstring. The drilling mud travels through a bore of the drillstring and exits through nozzles or ports of the drill bit or other drilling tools downhole. The drilling mud performs various functions, including, but not limited to, lubricating and cooling the cutting surfaces of the drill bit. Additionally, as the drilling mud returns to the surface through the annular space formed between the outer diameter of the drillstring and the inner diameter of the borehole, the mud carries cuttings away from the bottom of the hole to the surface. Once at the surface, the drill cuttings are filtered out from the drilling mud and the drilling mud may be reused and the cuttings examined to determine geological properties of the borehole.
Additionally, the drilling mud is useful in maintaining a desired amount of head pressure upon the downhole formation. As the specific gravity of the drilling mud may be varied, an appropriate “weight” may be used to maintain balance in the subterranean formation. If the mud weight is too low, formation pressure may push back on the column of mud and result in a blow out at the surface. However, if the mud weight is too high, the excess pressure downhole may fracture the formation and cause the mud to invade the formation, resulting in damage to the formation and loss of drilling mud.
As such, there are times (e.g., to replace a drill bit) where it is necessary to remove (i.e., “trip out”) the drillstring from the well and it becomes necessary to pump additional drilling mud (or increase the supply pressure) through the drillstring to displace and support the volume of the drillstring retreating from the wellbore to maintain the well's hydraulic balance. By pumping additional fluids as the drillstring is tripped out of the hole, a localized region of low pressure near or below the retreating drill bit and drill pipe (i.e., suction) may be reduced and any force required to remove the drillstring may be minimized. In a conventional arrangement, the excess supply drilling mud may be pumped through the same connection, between the top-drive and drillstring, as used when drilling.
As the drillstring is removed from the well, successive sections of the retrieved drillstring are disconnected from the remaining drillstring (and the top-drive assembly) and stored for use when the drillstring is tripped back into the wellbore. Following the removal of each joint (or series of joints) from the drillstring, a new connection must be established between the top-drive and the remaining drillstring. However, breaking and re-making these threaded connections, two for every section of drillstring removed, is very time consuming and may slow down the process of tripping out the drillstring.
Previous attempts have been made at speeding up the process of tripping-out. GB2156402A discloses methods for controlling the rate of withdrawal and the drilling mud pressure to maximize the speed of tripping-out the drillstring. However, the amount of time spent connecting and disconnecting each section of the drillstring to and from the top-drive is not addressed.
Another mechanism by which the tripping out process may be sped up is to remove several joints at a time (e.g., remove several joints together as a “stand”), as discussed in GB2156402A. By removing several joints at once in a stand (and not breaking connections between the individual joints in each stand), the total number of threaded connections that are required to be broken may be reduced by 50-67%. However, the number of joints in each stand is limited by the height of the derrick and the pipe rack of the drilling rig, and the method using stands still does not address the time spent breaking the threaded connections that must still be broken.
GB2435059A discloses a device which comprises an extending piston-rod with a bung, which may be selectively engaged within the top of the drillstring to provide a fluid tight seal between the drillstring and top-drive. This arrangement obviates the need for threading and unthreading the drillstring to the top-drive. However, a problem with the device disclosed therein is that the extension of the piston-rod is dependent upon the pressure and flow of the drilling mud through the top-drive. Whilst this may be advantageous in certain applications, a greater degree of control over the piston-rod extension independent of the drilling mud pressure is desirable.
Similarly, there may be applications where it is desirable to displace fluid from the borehole, particularly, for example, when lowering the drillstring (or a casing-string) in deepwater drilling applications. In such deepwater applications, the seabed accommodates equipment to support the construction of the well and the casing used to line the wellbore may be hung and placed from the seabed. In such a configuration, a drillstring (from the surface vessel) may be used as the mechanism to convey and land the casing string into position. As the drillstring is lowered, successive sections of drillstring would need to be added to lower the drillstring (and attached casing string) further. However, as the bore of the typical drillstring is much smaller than the bore of a typical string of casing, fluid displaced by the casing string will flow up and exit through the smaller-bore drillstring, at increased pressure and flow rates. As such, designs such as those disclosed in GB2435059A would not allow reverse flow of drilling mud (or seawater) as would be required in such a casing installation operation.
Embodiments of the present disclosure seek to address these and other issues of the prior art.